It is important to understand the effects of introducing thermal changes in the subsurface because such changes alter the state of stress and, ultimately, the behavior of the formation. Inducing fractures in the formation may cause injection fluids to advance at different rates through the reservoir, thereby reducing the areal sweep through the reservoir and the overall efficiency of a flooding operation. To avoid induced fractures, it is necessary to maintain water flooding operations below the fracturing (breakdown) pressure of the formation. For these reasons, it is extremely important to model the cold water injection response and to predict whether it is possible to inject without creating fractures in the formation.

In late 2006 a reservoir simulation study using ECLIPSE was performed for 103N Field in Sirte Basin to evaluate the reservoir response to water flooding in an attempt to understand the potential for improving oil and gas recovery with water flooding. This study showed that the main effect of cold water injection on the recovery of N- Field was reduced injectivity due to high water viscosity. Another effect of cold water injection was that bypassed oil was cooled down and its mobility was reduced due to the increase in the oil viscosity, thus reducing ultimate recovery.

This paper provides an extension of the reservoir simulation done by Wintershall to examine the effect of cold water injection on formation fracturing gradients. The work includes a review of the rock mechanics and stress analysis of the subsurface formations and provides an estimation of fracture penetration within the reservoir for a range of water injection rates and water surface temperatures. The conclusions of this study provide important insights into applying water flooding operations in the N-field.

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